No abstract

Summary In this study we compare real data from an Eagle Ford Shale huff ‘n’ puff (H&P) gas-injection pilot with reservoir simulation and tank material-balance calculations. The comparison is good and supports the conclusion that oil recovery from the Eagle Ford (and likely other shales) can be increased significantly using H&P. For H&P to work, the injected gas and the in-situ oil in the shale must be contained vertically and laterally following hydraulic fracturing. Containment is critical for the success of H&P. Containment implies that the injected gas flows into the hydraulic fractures, penetrates the tight matrix, and does not escape or leak outside the target stimulated reservoir volume (SRV). Vertical and lateral containment exists in the Eagle Ford as demonstrated previously (Ramirez and Aguilera 2016) with an upside-down distribution of fluids: Natural gas is at the bottom of the structure, condensate in the middle, and oil at the top. Two different matching and forecasting approaches are used in this study: reservoir simulation and tank-material-balance calculations. The results show a good history match of primary recovery and secondary recovery by H&P in the pilot well. The history match is good in the case of both reservoir simulation and tank material-balance calculations. Once a match is obtained, the simulation and material balance are used to forecast secondary recovery over a period of 10 years with sustained H&P injection of dry gas. The results indicate that dry-gas H&P can increase oil recovery from the Eagle Ford Shale significantly. Under favorable conditions, oil recovery can be doubled and even tripled over time compared with the primary recovery. The addition of heavier ends to the H&P gas injection can increase oil recovery even more, putting it on par with recoveries in conventional reservoirs. The benefit of H&P occurs in the case of both immiscible and miscible gas injection. The H&P benefits can likely be also obtained in other shale reservoirs with upside-down containment of dry gas, condensate, and oil. The novelty of this work is the combined use of reservoir simulation and tank material-balance calculations to match the performance of an H&P gas-injection pilot in the Eagle Ford Shale of Texas. We conclude that oil recoveries can be increased significantly by H&P.

The objective of this paper is to investigate the possibility of using gas injection to improve liquids recoveries from containers in shale condensate and shale oil reservoirs. Liquids recoveries from shales are known to be very low. A method is proposed to increase these recoveries through gas recycling and by using dry gas that is available within relatively short distances of the shale condensate and oil containers considered in this study. This dry gas is not being produced at this time due to current market conditions. In practice, some shale reservoirs such as the Eagle Ford in the United States and the Duvernay in Canada present the challenge of unconventional fluids distribution: shallower in the structure there is black oil, deeper is condensate and even deeper is dry gas. So the fluids distribution is exactly the opposite of what occurs in conventional reservoirs. Differences in burial depth, temperature, and vitrinite reflectance are used to explain this unique distribution. Ramirez and Aguilera (2014) have shown that fluids in shale reservoirs have remained with approximately the same original distribution (i.e. approximately the same dry gas-condensate contact and approximately the same condensate-oil contact) over geologic time. These fluids are the target of the research results presented in this paper. The investigation involves three basic cases, all of them with horizontal wells. In the first case, a single porosity compositional simulation is used to investigate the possibility of improved liquid recovery from the condensate container by using dry gas injection obtained from the recycling process plus dry gas from the deeper part of the structure. Fluid properties are similar to those of the Duvernay shale. In the second case, dual permeability compositional simulations are used to investigate practical aspects of the condensate container that can lead to improved recoveries in the Eagle Ford shale. Sensitivities are run that include bottomhole pressure (BHP), natural fracture permeability and spacing, hydraulic fracture length and spacing, and distance between parallel wells. Results from dual permeability simulations are compared with dual porosity behavior. Fluid properties are similar to those of the Eagle Ford shale. In the third case, compositional single porosity, dual porosity and dual permeability simulations are used to study the possibility of injecting gas in the oil container. A cyclic huff and puff gas injection is also investigated. Fluids and rock properties are similar to those of the Eagle Ford shale. The study leads to the conclusion that dry gas from deeper shales can be put to good use by injecting it into the middle and upper parts of the structure. In the middle part of the structure there is a container where gas condensate is predominant. In here, a re-cycling injection project allows to inject dry gas stripped from the condensate fluids. This is supplemented with dry gas produced from the deeper part of the structure. In the upper part of the structure there is a container where oil is predominant. In here, injection is implemented using dry gas produced from the deeper part of the structure. Permeability plays a critical role in the case of single porosity simulations. Dual porosity and dual permeability simulations indicate that oil recovery can be enhanced significantly in naturally fractured shales. Diffusion plays a fundamental role on the performance of shale gas injection particularly in the case of naturally fractured shales. It is found that cyclic huff and puff gas injection can help increase oil recovery. To the best of our knowledge, the idea developed in this paper that includes all fluids (oil, condensate and dry gas) present in the same shale structure within relatively short distances of each other has not been published previously in the literature.

A comparison is made of real data from an Eagle Ford huff-and-puff (H&P) gas injection pilot with reservoir simulation and tank material balance calculations. The comparison is good and supports the conclusion that oil recovery from the Eagle Ford (and likely other shales) can be increased significantly with the use of H&P. The study is based on the container methodology: for H&P to work, the injected gas and the insitu oil in the shale must be contained vertically and laterally following hydraulic fracturing. Containment is critical for the success of H&P. Vertical and lateral containment exist in the Eagle Ford as demonstrated previously (Fragoso et al., 2015) with the upside-down distribution of fluids: natural gas is at the bottom of the structure, condensate in the middle and oil at the top. Two different matching and forecasting approaches are used in this study: reservoir simulation and tank material balance calculations. Results show a good history match of primary recovery and secondary recovery by H&P in the pilot well. The history match is good in the case of both reservoir simulation and tank material balance calculations. Once a match is obtained, the simulation and material balance are used to forecast secondary recovery over a period of 10 years with sustained H&P injection of dry gas. Results indicate that dry gas H&P can increase oil recovery from the Eagle Ford shale significantly. Under favorable conditions, oil recovery can be doubled and even tripled over time compared with the primary recovery. The addition of heavier ends to the H&P gas injection can increase even more oil recoveries, putting them on par with conventional reservoirs. The benefit of H&P occurs both in the case of immiscible and miscible gas injection. The H&P benefits can likely be also obtained in other shale reservoirs with upside-down containers for dry gas, condensate and oil. The novelty of the work is the combined use of reservoir simulation and tank material balance calculations to match performance of an H&P gas injection pilot in the Eagle Ford shale of Texas. The conclusion is reached that oil recoveries can be increased significantly by H&P.

The objective of this paper is to compare oil recoveries by huff ‘n’ puff gas injection using methane (CH4), carbon dioxide (CO2), hydrogen (H2) and rich gas (70% CH4, 20% C3H8, plus 10% C6H14), and to advance some ideas regarding carbon capture, utilization and storage (CCUS) of CO2, and storage of hydrogen when these gases are used in huff ‘n’ puff operations. The procedure considers a real huff ‘n’ puff pilot well in the Eagle Ford shale of Texas with methane injection. Following history match of the pilot well, the injected gas is switched in the reservoir simulator to CO2, H2 and rich gas. Key to success in this process, is geologic containment, which occurs when large volumes of hydrocarbons remain over geologic time in the windows where they were generated. This is the case of the Eagle Ford shale, where hydrocarbons display an upside-down distribution, with oil on the top, condensate in the middle and dry gas at the bottom. Geologic containment permits the implementation of simultaneous huff ‘n’ puff, utilization and storage of CO2 with nil probabilities of leakage. Results show that huff ‘n’ puff gas injection can significantly increase oil recoveries to be 25-35% of the OOIP (depending on the specific injected gas), compared to about 10% by primary means during the simulation time. The benefits of huff ‘n’ puff gas injection are also applicable in other shale reservoirs where oil, condensate and dry gas present an upside down distribution. One example in Canada is the Duvernay shale. Geologic containment allows adequate and safe storage of CO2 and hydrogen without leaks at the end of the huff ‘n’ puff project. This paper also assesses and corroborates the conclusion that "significant improvements in oil recovery can be obtained by injecting gas at larger rates during shorter periods of time (as opposed to injecting gas at smaller rates during longer periods of time)." The same conclusion holds true for methane, CO2, hydrogen and rich gas injection. The novelty of this work is demonstrating the efficiency of CCUS and huff ‘n’ puff gas injection when geologic containment exists in the shale reservoir. It is a solution where everyone benefits and allows to significantly increase oil recoveries, while providing safe storage of CO2 and H2 without any leaks.